DALLAS, Feb. 27, 2017 /PRNewswire/ — RSP Permian, Inc. (“RSP” or the “Company”) (NYSE: RSPP) today reported financial and operating results for the quarter and year ended December 31, 2016, year-end 2016 proved reserves, 2017 guidance and 2018 and 2019 production outlook. In addition, the Company filed its Annual Report on Form 10-K for the year ended December 31, 2016 with the Securities and Exchange Commission (the “SEC”) and posted an updated presentation on its website at www.rsppermian.com.

Spanish Trail 344 two-well pad and Spanish Trail 341 two-well pad: Four 6,500′ lateral wells, with two wells each targeting the Wolfcamp A and Wolfcamp B formations, established a peak 30-day average rate of 6,212 Boe/d (79% oil) and produced in excess of 250,000 Boe in less than 60 days

2017 Guidance and 2018 and 2019 Production Outlook

Average net daily production range of 53.0 – 57.0 MBoe/d in 2017, an 82% – 95% increase over 2016

Development capital expenditure range of $625 – $700 million (drilling, completion, infrastructure and other) with drilling and completion of $575 – $625 million and infrastructure and other of $50 – $75 million

30%+ annual production growth profile in 2018 and 2019 with cash flow neutrality beginning in 2018 at $55 oil

Expanded hedge profile covering 55% of 2017E oil production and 64% of 2017E natural gas volumes at the midpoint. Entered into basis swaps to protect Midland–Cushing differentials and began layering in 2018 oil hedges

Steve Gray, Chief Executive Officer, commented, “I am pleased to report our fourth quarter and full year results, highlighted by annual production growth of nearly 40% with 25% less in capital expenditures as compared to last year. Importantly, we continued to operate efficiently with strong cash margins and record low drill-bit finding and development costs. During the year, we reduced our activity levels in response to depressed oil prices early in the year and remained patient on M&A opportunities until we identified high quality properties that would compete for capital in our existing portfolio. With our recent entry into the Delaware Basin through our $2.4 billion acquisition of Silver Hill, we believe we have assembled one of the most focused and highest returning asset bases in the Permian Basin, solidifying our ability to achieve outstanding growth and strong operating and capital efficiency for years to come.”

Mr. Gray continued, “I am also pleased to announce that our shareholders have overwhelmingly approved our issuance of RSP common stock to partially fund the SHEP II transaction which we expect to close Wednesday. We have already begun to integrate the Silver Hill assets into our inventory and are working towards achieving efficient, multi-zone horizontal development on the acquired properties. In addition, we recently acquired the underlying water disposal infrastructure supporting our operations in the Delaware. We are currently expanding these facilities and developing new facilities to support our growing operations and lower our operating costs. We are also working diligently with our various midstream partners and expect to be in position to ramp our drilling program beginning in the second half of 2017. Recent strong well results, which span five horizontal zones on the properties, highlight the attractive return profile in multiple stacked horizontal zones on our Delaware acreage position.”

Average prices shown in the table reflect prices both before and after the effects of our cash payments/receipts on our commodity derivative transactions. Our calculation of such effects includes realized gains or losses on cash settlements for commodity derivative transactions and an adjustment to reflect premiums incurred previously or upon settlement that are attributable to instruments settled in the period, if applicable.

(2)

Average prices for oil are net of transportation costs. Average prices for natural gas do not include transportation costs; instead, transportation costs related to our natural gas production and sales are included in gathering and transportation which is included in lease operating expenses in our consolidated statements of operations. No transportation costs are associated with NGL production and sales.

(3)

Represents compensation expense related to restricted stock awards and performance share awards granted as part of the Company’s ongoing compensation and retention programs.

(4)

Non-recurring stock comp in 2015 includes compensation expense related to the successful completion of the Company’s initial public offering and related expenses associated with one-time restricted stock awards. The non-recurring 2016 amount is a compensation charge associated with the retirement of an officer of the Company.

Production volumes for the quarter ended December 31, 2016 averaged 35,793 Boe/d or a total of 3,293 MBoe, an increase of 48% over prior year’s fourth quarter of 24,250 Boe/d. Production for the fourth quarter of 2016 was comprised of 71% crude oil, 12% natural gas and 17% NGLs. RSP’s average realized commodity price per barrel of oil equivalent for the fourth quarter of 2016, before the effects of hedges, was $37.33. RSP’s average realized oil price for the fourth quarter of 2016, before the effects of hedges, was $47.23 per barrel, a negative $2.06 differential compared to average NYMEX WTI pricing of $49.29 per barrel for the same period, or 96% of NYMEX WTI pricing. RSP’s average realized natural gas price for the fourth quarter of 2016, before the effects of hedges, was $2.24 per Mcf, a negative $0.74 differential compared to average NYMEX Henry Hub pricing of $2.98 per MMBtu for the same period, or 75% of NYMEX Henry Hub pricing. RSP’s average realized NGL price for the fourth quarter of 2016, before the effects of hedges, was $12.94 per Bbl, or 26% of NYMEX WTI pricing for the same time period. Per unit cash operating expenses excluding interest expense but including lease operating expense, gathering and transportation expense, production and ad valorem taxes and recurring cash general and administrative expenses were $9.11 per Boe, an 9% decrease from prior year’s comparable quarter.

Production volumes for the year ended December 31, 2016 averaged 29,161 Boe/d or a total of 10,673 MBoe, an increase of 39% over prior year’s total of 21,047 Boe/d. Production for 2016 was comprised of 73% crude oil, 11% natural gas and 16% NGLs. RSP’s average realized commodity price per barrel of oil equivalent for 2016, before the effects of hedges, was $33.15. RSP’s average realized oil price for 2016, before the effects of hedges, was $41.28 per barrel, a negative $2.04 differential compared to average NYMEX WTI pricing of $43.32 per barrel for the same period, or 95% of NYMEX WTI pricing. RSP’s average realized natural gas price for 2016, before the effects of hedges, was $1.94 per Mcf, a negative $0.52 differential compared to average NYMEX Henry Hub pricing of $2.46 per MMBtu for the same period, or 79% of NYMEX Henry Hub pricing. RSP’s average realized NGL price for 2016, before the effects of hedges, was $10.87 per Bbl, or 25% of NYMEX WTI pricing for the same time period. Per unit cash operating expenses excluding interest expense but including lease operating expense, gathering and transportation expense, production and ad valorem taxes and recurring cash general and administrative expenses were $9.54 per Boe, a 19% decrease from prior year’s comparable total.

Operational Update

The Company operated three horizontal rigs in the Midland Basin during the fourth quarter, and upon closing the acquisition of SHEP I, operated one rig in the Delaware Basin during December. RSP utilized one full-time completion crew during the fourth quarter in the Midland Basin and a part-time crew in the Delaware Basin during December. RSP drilled 13 operated horizontal wells and completed 14 operated horizontal wells (seven Lower Spraberry, three Wolfcamp A, three Wolfcamp B and one Avalon) and two operated vertical wells during the fourth quarter. The Company began the quarter with 12 operated horizontal drilled but uncompleted wells (“DUCs”) and exited the quarter with a total of 11 operated horizontal DUCs. During 2016, RSP drilled 46 and completed 53 operated horizontal wells (one Middle Spraberry, 35 Lower Spraberry, eight Wolfcamp A, eight Wolfcamp B and one Avalon) and drilled four and completed six operated vertical wells.

4Q16 Wells

2016 Wells

Drilled

Completed

Drilled butUncompletedWells (DUCs)

Drilled

Completed

Operated Wells

Horizontal

13

14

11

46

53

Vertical

—

2

—

4

6

Total Operated

13

16

11

50

59

Non-Operated Wells

Horizontal

6

13

11

35

37

Vertical

—

—

—

1

1

Total Non-Operated

6

13

11

36

38

Total Wells

Horizontal

19

27

22

81

90

Vertical

—

2

—

5

7

Total Wells

19

29

22

86

97

Financial Results

(In thousands, except per share data)

Three Months Ended

Twelve Months Ended

December 31,

December 31,

2016

2015

2016

2015

Total Revenues

$

122,934

$

73,508

$

353,857

$

283,992

Net Cash from Derivative Instruments

(2,398)

23,122

(1,732)

92,118

Adjusted Total Revenues

120,536

96,630

352,125

376,110

Net Income (Loss)

$

1,381

$

(20,751)

$

(24,851)

$

(18,254)

Net Income (Loss) per Common Share – Diluted

0.01

(0.21)

(0.23)

(0.21)

Adjusted Net Income (Loss) (1)

13,395

12,074

(7,358)

48,630

Adjusted Net Income (Loss) per Common Share – Diluted

0.10

0.12

(0.07)

0.56

Adjusted EBITDAX (1)

$

90,529

$

74,367

$

250,326

$

285,058

(1)

Adjusted EBITDAX and Adjusted Net Income are non-GAAP financial measures. For a definition of Adjusted EBITDAX and Adjusted Net Income and a reconciliation of Adjusted EBITDAX and Adjusted Net Income to Net Income, see “Use of Non-GAAP financial measures” and our quarterly statements of operations at the end of this release.

For the quarter ended December 31, 2016, total revenues, excluding the revenue impact from realized derivative instruments, were $122.9 million, a 67% increase over the prior year quarter of $73.5 million. Adjusted total revenues, including the net cash from derivative instruments, were $120.5 million, an increase of 25% over the prior year quarter of $96.6 million. Net income for the fourth quarter of 2016 was $1.4 million, or approximately one cent per diluted share, while net loss for the fourth quarter of 2015 was $20.8 million, or negative $0.21 per diluted share. Adjusted net income for the quarter was $13.4 million, or $0.10 per diluted share, compared with adjusted net income for the prior year quarter of $12.1 million or $0.12 per diluted share. Adjusted EBITDAX for the quarter ended was $90.5 million, an increase of 22% over the prior year quarter of $74.4 million.

For the year ended December 31, 2016, total revenues, excluding the revenue impact from realized derivative instruments, were $353.9 million, a 25% increase over the prior year of $284.0 million. Adjusted total revenues, including the net cash from derivative instruments, were $352.1 million, an decrease of 6% from the prior year of $376.1 million. Net loss for the year ended 2016 was $24.9 million, or negative $0.23 per diluted share, while net loss for the year ended 2015 was $18.3 million, or negative 0.21 per diluted share. Adjusted net loss for the year ended 2016 was $7.4 million, or negative $0.07 per diluted share, compared with adjusted net income for the prior year of $48.6 million or $0.56 per diluted share. Adjusted EBITDAX for the year ended 2016 was $250.3 million, a decrease of 12% from the prior year ended 2015 of $285.1 million.

Proved Reserves Summary

RSP’s proved reserves summary as of December 31, 2016 and pro forma proved reserved summary as of December 31, 2016 were prepared by Netherland, Sewell & Associates, Inc.

Our December 31, 2016 proved reserves summary included reserves from the SHEP I acquisition that closed on November 28, 2016 and totaled 236.9 MMBoe. Pro forma for the SHEP II acquisition, which is expected to close on March 1, 2017, our total proved reserves as of December 31, 2016 were 283.3 MMBoe. The Company removed its remaining economic reserves associated with vertical proved undeveloped locations from its proved reserve base due to the superior economics of horizontal drilling locations which are expected to be drilled in front of the vertical locations over the next five years. This resulted in a 23.4 MMBoe downward revision to proved reserves offset by positive revisions from horizontal wells that are performing above previous estimates, resulting in total downward revisions of previous estimates of 17.8 MMBoe.

The following table presents the Company’s estimated net proved oil and natural gas reserves as of December 31, 2016 (excluding SHEP II acquisition) and net proved oil and natural gas reserves as of December 31, 2015, and in each case, prepared in accordance with the rules and regulations of the SEC.

Oil

(MBbls)

Natural

Gas

(MMcf)

NGLs

(MBbls)

Total

(MBoe)

Proved developed and undeveloped reserves:

As of December 31, 2015

111,135

133,507

25,787

159,173

Revisions of previous estimates

(14,115)

(30,284)

1,412

(17,750)

Extensions, discoveries and other additions

46,017

45,541

11,631

65,238

Purchases of minerals in place

29,481

35,210

5,551

40,900

Production

(7,790)

(7,188)

(1,685)

(10,673)

As of December 31, 2016

164,728

176,786

42,696

236,888

The following table presents the Company’s estimated net proved oil and natural gas reserves as of December 31, 2016, 2015 and 2014, as well as our pro forma net proved oil and natural gas reserves as of December 31, 2016, after giving effect to the SHEP II acquisition as if it had occurred before December 31, 2016.

Pro Forma 2016

2016

2015

2014

Proved developed reserves:

Oil (MBbls)

75,341

65,025

44,128

27,716

Natural gas (MMcf)

86,475

76,255

56,640

35,921

NGLs (MBbls)

20,864

18,759

11,020

8,221

Total (MBoe)

110,617

96,493

64,588

41,924

Proved undeveloped reserves:

Oil (MBbls)

123,601

99,703

67,007

41,557

Natural gas (MMcf)

122,959

100,531

76,867

56,501

NGLs (MBbls)

28,575

23,937

14,767

13,518

Total (MBoe)

172,669

140,395

94,585

64,492

Total proved reserves:

Oil (MBbls)

198,942

164,728

111,135

69,273

Natural gas (MMcf)

209,434

176,786

133,507

92,422

NGLs (MBbls)

49,439

42,696

25,787

21,739

Total (MBoe)

283,286

236,888

159,173

106,416

Capital Expenditures

RSP’s development capital expenditures, which includes our investment in drilling and completing wells, infrastructure, capitalized workovers, and other, but excludes acquisitions, for the year ended December 31, 2016 totaled $294 million ($275 million of drilling and completion and $19 million of infrastructure and other). The Company spent approximately $57 million, or 19% of development capital, on non-operated properties. Additionally, during 2016 the Company closed approximately $69 million of acquisitions and additions to leasehold in the Midland Basin and closed the SHEP I acquisition for approximately 15 million shares of RSP stock and $604 million in cash.

On October 13, 2016, the Company priced an underwritten public offering of 25.3 million shares of RSP common stock, including the exercise of the underwriters’ option to purchase additional shares, raising approximately $1.0 billion in net proceeds. On December 12, 2016, RSP priced $450 million aggregate principal amount of 5.25% senior unsecured notes due 2025 at par. RSP used a portion of the net proceeds raised in these offerings to fund the cash portion of the SHEP I acquisition and will use the balance of the proceeds to fund the cash portion of the SHEP II acquisition.

On December 20, 2016, RSP announced it entered into an amended and restated credit agreement with respect to the Company’s senior secured revolving credit facility. The amended and restated credit agreement extended the maturity date of the facility until December 19, 2021, increased the borrowing base under the facility to $950 million and increased the maximum commitments of the lenders from $1.0 billion to $2.5 billion. The $950 million borrowing base only reflected the reserve growth from the Company’s Midland Basin assets and the previously closed SHEP I acquisition. Upon closing the SHEP II acquisition, RSP’s borrowing base will automatically increase to $1.1 billion. RSP elected an aggregate commitment amount of $900 million under the facility and will leave this amount unchanged upon the closing of SHEP II.

As of December 31, 2016, the Company had no borrowings outstanding on its revolving credit facility and had $691 million of cash on hand. Pro forma for closing the acquisition of SHEP II, as of December 31, 2016, the Company had $109 million of cash and no borrowings outstanding on its revolving credit facility, which has a $1.1 billion borrowing base and a $900 million Company elected commitment.

Hedging

The summary below includes all hedges in place for the full year 2017 and 2018, as of February 27, 2017.

Crude Oil Hedges

(Bbl, $/Bbl)

Q1 2017

Q2 2017

Q3 2017

Q4 2017

2018

Three-Way Collars(1)

675,000

3,160,000

Ceiling

$

54.25

$

65.06

Floor

$

45.00

$

50.00

Short Put

$

35.00

$

40.00

Costless Collars(1)

450,000

1,137,500

1,150,000

1,150,000

Ceiling

$

59.75

$

60.05

$

60.05

$

60.05

Floor

$

45.00

$

45.00

$

45.00

$

45.00

Deferred Premium Puts(1)

910,000

920,000

920,000

Floor

$48.50

$48.50

$48.50

Deferred Premium(2)

($4.00)

($4.00)

($4.00)

Deferred Premium Put Spreads(1)

675,000

Floor

$45.00

Short Put

$35.00

Deferred Premium(2)

($2.32)

Total Hedge Volumes

1,800,000

2,047,500

2,070,000

2,070,000

3,160,000

Weighted Average Floor(3)

$

44.13

$

44.78

$

44.78

$

44.78

$

50.00

Mid-Cush Differential Swaps:

1,881,000

2,548,000

920,000

276,000

Swap(4)

$

(0.14)

$

(0.11)

$

(0.38)

$

(0.50)

(1)

The crude oil derivative contracts are settled based on the arithmetic average of the closing settlement price for the front month contract NYMEX price of West Texas Intermediate Light Sweet Crude.

(2)

The deferred premium is not paid until expiration date, aligning cash inflows and outflows with the settlement of the derivative contract.

(3)

Weighted average floor assumes the long put in three way collars and put spreads and reflects the impact of premiums paid

(4)

The Mid-Cush swap contracts are settled based on the difference in the arithmetic average during the calculation period of WTI MIDLAND ARGUS and WTI ARGUS prices in the Argus Americas Crude publication for the relevant period.

Natural Gas Hedges

(MMBtu, $/MMBtu)

Q1 2017

Q2 2017

Q3 2017

Q4 2017

Costless Collars(1)

1,955,000

2,366,000

2,422,000

2,545,000

Ceiling

$

3.83

$

3.86

$

3.86

$

3.86

Floor

$

3.00

$

3.00

$

3.00

$

3.00

(1)

The natural gas derivative contracts are settled based on the last trading day’s closing price for the front month contract relevant to each period.

2017 Annual Guidance

RSP’s operating plan is expected to build momentum in the back half of 2017. After growing production an estimated 82% – 95% in 2017, both organically and with the production volumes associated with the Silver Hill acquisition, the Company anticipates it will deliver annual production growth in excess of 30% in both 2018 and 2019 while being cash flow neutral beginning in 2018 at a $55 oil price.

As a result of the staggered closing of the Silver Hill transactions and the anticipated rig additions during the year, the investment of capital expenditures is expected to be approximately 60 – 70% in the Midland Basin and 30 – 40% in the Delaware Basin for a total developmental capital budget of $625 million to $700 million.

The Company recently deployed a fourth operated rig on its Midland Basin properties earlier than anticipated in mid-January and plans to operate at least four rigs on its Midland assets for the balance of the year. RSP is currently operating one rig on its Delaware properties and will have a second operated rig working upon closing SHEP II. RSP anticipates adding a third operated rig on its Delaware properties after enhancing infrastructure to enable more efficient horizontal development. Additionally, RSP anticipates adding an additional operated rig during the fourth quarter and at that time will have a total of eight operated rigs.

The call may be accessed live over the telephone by dialing (877) 705-6003, or for international callers, (201) 493-6725. A replay will be available shortly after the call and can be accessed by dialing (844) 512-2921, or for international callers (412) 317-6671. The passcode for the replay is 13654848. The replay will be available until March 14, 2017. Interested parties may also listen to a simultaneous webcast of the conference call by logging onto RSP’s website at www.rsppermian.com in the Investor Relations section. A replay of the webcast will also be available following the call.

About RSP Permian, Inc.

RSP is an independent oil and natural gas company focused on the acquisition, exploration, development and production of unconventional oil and associated liquids-rich natural gas reserves in the Permian Basin of West Texas. The vast majority of our acreage is located on large, contiguous acreage blocks in the core of the Midland and Delaware Basins, sub-basins of the Permian Basin. The Company’s common stock is traded on the NYSE under the ticker symbol “RSPP.” For more information, visit www.rsppermian.com.

Forward-Looking Statements

This news release contains forward-looking statements within the meaning of the federal securities laws. All statements, other than historical facts, that address activities that RSP assumes, plans, expects, believes, intends or anticipates (and other similar expressions) will, should or may occur in the future are forward-looking statements. Forward-looking statements are based on management’s current beliefs, based on currently available information, as to the outcome and timing of future events. These forward-looking statements involve certain risks and uncertainties that could cause the results to differ materially from those expected by the management of RSP. Information concerning these risks and other factors can be found in RSP’s filings with the SEC, including its Annual Reports on Form 10-K and Quarterly Reports on Form 10-Q, which can be obtained free of charge on the SEC’s web site located at http://www.sec.gov. RSP undertakes no obligation to update or revise any forward-looking statement.

We define Adjusted EBITDAX as oil and gas revenues including net cash receipts (payments) on settled derivative instruments and premiums paid on put options that settled during the period, less lease operating expenses, production and ad valorem taxes, and general and administrative expenses excluding stock based compensation. Adjusted Net Income deducts from Adjusted EBITDAX depreciation, depletion, and amortization, accretion on asset retirement obligations, exploration expenses, interest expense, stock-based compensation, acquisition costs and adjusted income tax expense.

Management believes Adjusted EBITDAX and Adjusted Net Income are useful because they allow us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above in arriving at Adjusted EBITDAX and Adjusted Net Income because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX and Adjusted Net Income should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDAX and Adjusted Net Income are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDAX. Our computations of Adjusted EBITDAX and Adjusted Net Income may not be comparable to other similarly titled measures of other companies.

The following tables include a reconciliation of the non-GAAP financial measures of Adjusted EBITDAX and Adjusted Net Income to the GAAP financial measure of net income.